Sept. 30 (Bloomberg) -- The 15 mile-per-hour winds that
buffeted northern Germany on July 24 caused the nation’s 21,600
windmills to generate so much power that utilities such as EON
AG and RWE AG had to pay consumers to take it off the grid.

Rather than an anomaly, the event marked the 31st hour this
year when power companies lost money on their electricity in the
intraday market because of a torrent of supply from wind and
solar parks. The phenomenon was unheard of five years ago.

With Europe’s wind and solar farms set to triple by 2020,
utilities investing in new coal and gas-fired power stations no
longer face stable returns. As more renewables come on line, a
gas plant owned by RWE or EON that may cost $1 billion to build
will be stopped more often from running at full capacity. It may
only pay for itself on days like Jan. 31, when clouds and still
weather pushed an hour of power on the same-day market above 162
($220) euros a megawatt-hour after dusk, in peak demand time.

“You’re looking at a future where on a sunny day in
Germany, you’ll have negative prices,” Bloomberg New Energy
Finance chief solar analyst Jenny Chase said about power rates
in wholesale trading. “And a lot of the other markets are
heading the same way.”

Europe’s biggest power markets give preference to renewable
energy including forcing some utilities to use their fossil-fuel
plants less. That cuts into profit, complicating investment
decisions as the companies try to meet emission targets and
replace older plants and networks that Citigroup Inc. estimates
will cost them more than 900 billion euros by 2020.

Profit Margins

Northern Europe’s renewable-energy goals call for about 200
gigawatts of solar and wind capacity by 2020, or almost a third
of the current installed base, compared with about 70 gigawatts
today, according to the Finnish energy consultant Poyry. Even by
2014, gross profit from burning coal in Germany may skid by as
much as 41 percent, according to Barclays Plc.

The gross margin at a coal power plant after deducting fuel
and emission permit costs, the so-called clean dark spread, may
“collapse” to as low at 3.50 euros a megawatt-hour, Barclays
analysts including Peter Bisztyga said in a Sept. 1 report. The
spread was at 6.15 euros today, Bloomberg data show.

Narrower margins mean it will take longer for companies to
pay off building new gas- and coal-fired facilities. Those
plants are needed. They can run around the clock, preventing
blackouts when the sun sets or the wind dies as European power
demand grows 5 percent through 2015 compared with 2010,
according to Paris-based bank Societe Generale SA’s forecast.

‘Squeezed Out’

“The more intermittent technology like renewables, the
more baseload generation will be squeezed out,” Volker Beckers,
chief executive officer of RWE’s U.K. Npower unit, said in an
interview at Bloomberg’s London bureau. Npower’s plants are
largely coal- and gas-fired, or baseload, meaning they can run
around the clock.

Electricite de France SA is spending 6 billion euros on its
new 1,650-megawatt nuclear reactor at Flamanville in Normandy.
Dong Energy A/S, Denmark’s biggest utility, inaugurated its
first power station in the U.K. in February, an 824-megawatt
combined-cycle gas turbine plant for 600 million pounds.

Europe’s 30-member STOXX 600 utilities index has fallen 15
percent this year. RWE has slumped 44 percent since January and
closed at 27.72 euros today in Frankfurt trading. EON, which has
skidded 29 percent since January, announced plans last month to
cut 10 percent of its workers and reduce dividends.

EON, RWE

EON will miss its 2015 forecast by about 3 percent for
earnings of 13.3 billion euros to 13.8 billion euros before
interest, tax, depreciation and amortization if average power
prices are 57.30 euros a megawatt-hour, below EON’s forecast of
60 to 62 euros, UniCredit analyst Lueder Schumacher said.

At 58.50 euros, RWE’s recurring net income will be 2.2
billion euros in 2013, compared with the German utility’s
forecast of 2.5 billion, he estimated.

“Too much wind can depress power prices, but then there
are times when very little wind is blowing,” Poyry Director
Phil Hare said in a telephone interview.

Based on weather patterns over the past 10 years, there’s a
72-hour period each year when a wind farm would produce less
than 5 percent of its potential output, Hare said. “Some other
plant has to be there, but the company has to make the return on
its investment in just those 72 hours over 10 years.”

Hedging Power Output

Germany’s renewable energy boom will make hedging the power
output for utilities’ coal and natural-gas plants “more and
more difficult,” according to an executive at Edison Trading
SpA speaking at a conference in London.

The country’s renewable energy output may rise to 200
terawatt-hours in 2020 from 120 terawatt-hours last year, Andrea
Siri, Edison’s head of continental power and origination, said
yesterday, citing a regulatory forecast.

Solar plants in Germany generated as little as 23.8
megawatts at 7 a.m. Berlin time yesterday compared with 11,570
megawatts at 1:30 p.m., according to a European Energy Exchange
AG’s website, tracking power capacity. A steady supply of 1,000
megawatts is enough for about 2 million homes in Germany.

Power prices on the Epex Spot SE exchange in Paris that
handles German and French supply vary hour-by-hour depending on
how available capacity is. At times they can become negative
when renewable energy peaks and there’s a surplus of power.

Take Renewable Output

At such times, generators or the grid operator pay
consumers to take their electricity if they aren’t able to
reduce output or hedge it. Grid operators in Germany, Europe’s
biggest power market, are also required to take renewable output
if it is available, just as in Spain and France.

The highest-ever hourly price in the combined German-French
intraday market was 162.06 euros a megawatt-hour for delivery
between 6 p.m. and 7 p.m. in Germany on Jan. 31, while the
lowest was minus 55.11 euros for 2 p.m. to 3 p.m. on Feb. 6,
data from the exchange showed.

The negative German prices on July 24 occurred on a day
when winds averaged 15 mph in the northern state of Mecklenburg-Western Pomerania, home to many wind farms, Bloomberg weather
data show.

Germany’s same-day electricity price was below zero for
nine hours on that windy day on July 24, with negative prices
for a total of 31 hours so far in 2011, according to Epex data.
France had 9 negative hours this year.

‘Buffer the Volatility’

The joint French-German intraday market started last year
and has so far helped to “buffer the volatility of prices,”
Epex company spokesman Wolfram Vogel said by e-mail on Sept. 16.

“The law in Germany is that renewables have priority, so
utilities have the choice of turning plants down for a few hours
or paying a negative price to someone in Germany or abroad,”
EON spokesman Georg Oppermann said in a telephone interview. The
company’s traders can protect EON against losses by watching
weather patterns, he added.

“The huge amount of renewable capacity due to be added to
the grid will depress not just spreads but also the outright
power price,” UniCredit analyst Scott Phillips said. “This is
clearly a negative predominantly for all thermal power plants,
particularly coal.”

Britain plans to install more than 8,000 offshore wind
turbines by 2020 to get 15 percent of electricity from renewable
sources. Germany installed 7.4 gigawatts of solar photovoltaic
capacity last year, the most of any nation, driving total
capacity to 17,200 megawatts. Spain aims to get 20.8 percent of
its total energy from marine energy, geothermal and offshore
wind projects, as well as hydropower, by 2020.

Negative Prices

German wind power capacity peaked at close to 12,000
megawatts on July 24, according to Meteogroup data, the last day
of negative prices. Four days later, the most that the country’s
wind parks generated was 315 megawatts.

Photovoltaic and solar-thermal plants may meet most of the
world’s demand for electricity by 2060 -- and half of all energy
needs -- with wind, hydropower and biomass plants supplying much
of the remaining generation, the International Energy Agency
said in August.

U.K. energy regulator Ofgem is considering paying
generators to keep plants open as back-up suppliers,
compensating them for down time. The so-called capacity
payments, which also are being studied in Germany, are likely to
favor gas over coal, as gas plants can be turned on and off
faster, according to Phillips.

Feed-In Tariffs

Subsidized power rates called feed-in tariffs, a proposed
carbon floor price in Britain and other measures favoring
renewable projects will lead to a shift in the “merit order”
of plants across Europe, he said. Power from renewable projects
will be the first to be used, followed by gas-fired power
plants, which release less carbon-dioxide than coal stations.

“Margins are going to get worse over the next few years
but as the value of the plant for backup starts getting
interest, it becomes an issue of what they’re worth, not what
they cost,” Hare said.